The general procedure of drilling an oil or gas well includes drilling a borehole using a drilling fluid. Subsequent to drilling the borehole, casing is run into the well, preparatory to placing cement slurry in the annulus between the outside of the casing and the borehole wall. In order to obtain a good cementing job, it is necessary to displace substantially all of the drilling fluid or mud in the annulus with cement. This necessity arises from the fact that undisplaced mud and filter cake become the source of unsuccessful cement jobs since drilling fluids and cements are usually incompatible. Thus, most water base muds will either cause instant setting of the cement or act as a retarder of the cement setting that can adversely affect the strength of the cement. On the other hand, most cement slurries will flocculate and thicken most water base muds. As the cement is pumped out of the bottom of the casing and up the annulus, it may form flow channels through blocking sections of flocculated drilling mud. In addition, undisplaced filter cake can prevent cement from bonding to the formation and becomes the source of the flow channels.
U.S. Pat. No. 5,382,290 to Shell Oil Co. teaches that one of the major objectives of a primary cementing is to obtain good zonal isolation in the annulus of the well. Effective zonal isolation is achieved by sealing the cement and borehole wall. The interface of the cement and borehole wall is usually an interface between the cement and drilling fluid filter cake which is the source of many cementing problems. Good zonal isolation can be achieved if the filter cake hardens, permanently bonds to the formation face and the cement, and provides hydraulic sealing.
U.S. Pat. No. 5,464,060 assigned to Shell Oil Co. discloses a composition for use in drilling and cementing a well, thus avoiding removal of the drilling fluid, since the composition can be employed for both functions. The “universal drilling fluid” comprises the product of a drilling mud admixed with a hydraulic material which is suitable for drilling a borehole and laying down a settable filter cake on the walls of said borehole; and an activator admixable with or contacting the filter cake, the activator being functional to cause the filter cake to harden and set up. A preferred way of applying the activator is to conduct a normal cement job with a cement or mud-concrete slurry which carries the activator. The activator may also be admixed with a mud, a spotting fluid, or a pill and the resulting fluid may be spotted or circulated through the annulus prior to cementing. The activator is subsequently filtered (diffused) through the filter cake and causes it to set hard.
The advantages realized by the Shell invention include the following: (1) a universal fluid is functionally and rheologically suitable as a drilling fluid; (2) the settable filter cake laid down by the universal fluid hardens to a relatively high compressive strength, for example, about 3,500 psi; (3) improved zonal isolation is achieved by the settable filter cake which bonds to the formation and the cementing medium; (4) the bond between the hardened filter cake and the cementing medium is very strong; and (5) it is not necessary either to displace mud or to remove the mud filter cake when a universal fluid is used as a drilling fluid in a well.
Achieving good solution viscosity is important because the drilling fluid must be stable under high temperature conditions—the deeper the well the hotter is the surrounding earth. Additionally important time constraints are desired, where it may take 4 to 6 hours to pump a drilling fluid into a very deep well bore, but then the drilling fluid must gel and thicken quickly. Contrarily, waiting 24 or more hours for Portland cement to gel is expensive and runs the risk that within the set time conditions may change in the well that presents additional obstacles to sealing a well.
U.S. Pat. No. 7,267,174 to Halliburton Energy Services achieves the time restraints by reducing the amount of cement employed. The amount of cement in the sealant compositions is reduced by an effective amount to lengthen the gel time of the sealant compositions to greater than or equal to about 4 hours when the composition is exposed to ambient temperatures in the wellbore. In an embodiment, the gel time is in a range of from about 4 hours to about 12 hours, alternatively, from about 4 to about 8 hours, alternatively, from about 4 to about 6 hours. In particular, the amount of cement present in the sealant compositions may be in a range of from about 0% to about 50% by weight of the sealant composition. Thus, cementless sealant compositions are contemplated in one embodiment. As used herein, gel time is defined as the period of time from initial mixing of the components in the sealant composition to the point when a gel is formed. Further, as used herein, a gel is defined as a crosslinked polymer network swollen in a liquid medium.
U.S. Pat. No. 6,082,456 to Wecem AS discloses sealing oil and gas wells with a composition containing monomers, an initiator for heat induced production of free radicals, and a pot life extending inhibitor for stabilizing free radicals. Acrylate monomers are employed with organic peroxides as an initiator. This composition is not a drilling fluid. It is a cement substitute.
U.S. Pat. Nos. 7,343,974 and 7,696,133 to Shell Oil co. disclose a composition comprising vinyl ester of a C9 to C11 Versatic™ acid, at least one di- or tri-functional acrylate or methacrylate monomer, peroxide initiator, and unsaturated styrenic block copolymer, namely Kraton™ D triblock copolymers. Weighting agents like barite (barium sulfate) are incorporated in the composition. This composition had exceeded the desired solution viscosity and the compression strength was too low, and therefore it was not a good candidate as a universal fluid.
Generally there is a trade-off between solution viscosity and compression strength. To obtain a solution viscosity that allows the fluid to be pumped for 4 to 6 hours, the solution viscosity should not exceed about 1000 cP at room temperature. Low solution viscosity not only requires less energy consumption, but it also prevents any damage to weak formations around the wellbore. However the higher the desired compression strength, the higher the solution viscosity. To obtain compression strengths similar to Portland cement, the solution viscosity was too high, until the present invention.
Accessing low margin, highly fractured, and other challenged reservoirs has become increasingly difficult using traditional cement materials. Synthetic cement that has a low solution viscosity, high compressive strength and mechanical properties, improved performance in the presence of hydrocarbon contamination, and which can be controllably set in a desired zone would allow greater access to such challenging wells.
There exists a need in the oilfield for materials with low rheological profiles (similar to a typical oil-based drilling fluid) that can be controllably set into a composite material with compressive strength comparable to traditional Portland-based cement. Additionally, it is well known that hydraulic cements do not perform well in the presence of oil based mud. A material that possesses improved retention of mechanical properties in the presence of at least 20 wt. % oil based mud contamination (i.e., at least about 400 psi compressive strength) would therefore be highly desirable, as it may eliminate the need for both hole clean-out prior to cementing the well as well as the use of spacer fluids. Another concern with traditional cement is its high modulus, which lends itself to fracturing when placed under a strain greater than ˜5%; a semi-ductile synthetic cement material would therefore be able to withstand the effects of greater temperatures swings in the wellbore throughout the lifetime of the cement.